Amicus Curiae Brief — Environmental Defense v. Duke Energy Corporation

28 FILED

SEP 15 2006

No. 05-848

“OPPICEOPTHE CLERK

SUPREME COURT, U.S.

IN THE

Supreme Court of the Anited States

ENVIRONMENTAL DEFENSE, ET AL.,

Petitioners,

V.

DUKE ENERGY CORPORATION,

Respondent.

' On Writ of Certiorari to the United States Court of Appeals

for the Fourth Circuit

BRIEF AMICI CURIAE OF

THE AMERICAN PUBLIC POWER ASSOCIATION

AND THE NATIONAL RURAL ELECTRIC

COOPERATIVE ASSOCIATION

IN SUPPORT OF RESPONDENT DUKE ENERGY

JANET PITTERLE HOLT*

738 West Glebe Road

Alexandria, VA 22305

(703) 684-6102

RAE E. CRONMILLER

RICHARD H. ROBINSON

NRECA

4301 Wilson Boulevard

Arlington. VA 22203

(703) 907-5791

* Counsel of Record Counsel for Amici Curiae

WILSON-EPES PRINTING CO., INC. ~ (202) 789-0096 — WASHINGTON, D.C. 20001

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TABLE OF CONTENTS

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STATEMENT OF INTEREST OF AMICI CURIAE .........0.0000000+ l

SUMMARY OF ARGUMENT ..0.0cccccscceccccsccscssssevsesesssosesessesesscrees 4

I. REQUIRING NSR PERMITTING, A LENGTHY

AND COSTLY PROCESS, FOR REPAIRS THAT

DO NOT INCREASE A FACILITY’S

ACHIEVABLE HOURLY EMISSIONS RATE

WOULD SERIOUSLY IMPEDE THE ABILITY

OF PUBLIC AND RURAL COOPERATIVE

GENERATING SYSTEMS TO SUPPLY

RELIABLE AND AFFORDABLE ELECTRIC

PTT 00: wicermnestinasantennentnandapenagnemapnicnnieesaectimtasenenmectad 5

A. Public Power and the Nation’s Electric

Cooperatives Have a Duty to Provide

Reliable and Affordable Electric Service................... 5

B. Small Electric Generating Systems Often

Rely On Just a Few Units and Must Be Able

to Make Repairs to a Unit Without Taking

that Unit Offline For an Extended Period of

C. Requiring NSR Permitting For Repairs That

Do Not Increase Achievable Hourly

Emission Rates Would Present Small

Utilities With a Hobson’s Choice....................0.ccc00000 7

1. The NSR_ Permitting Process is

Expensive, Time-consuming and Often Not

RET Ise es a Oe eee eS RT 9

2. Obtaining a Synthetic Minor Permit is

Not a Rational, Economically Feasible or

Financially Prudent Alternative......................:.000000 11

il

TABLE OF CONTENTS—Continued

Page

3. For Even a Short Period, the Cost of

Replacement Power During NSR Permitting

Could Be Crippling For Many Public Power

and Rural Cooperative Systems...... ..............scee+esee+ 14

4. Requinng NSR Permitting For Repairs

That Do Not Increase a Unit’s Achievable

Hourly Emissions Rate Would Subject

Small Utilities to Constant NSR Permitting

or Compromise of Capacity. .............ccccsecsceeeseeeeeeees 16

5. The Potential Liability For Public Power

and Cooperatives is Great..................:cccccesseseseeeeeeees 18

Il. USE OF THE NSPS DEFINITION OF

"MODIFICATION" WILL NOT CIRCUMVENT

CONGRESS' INTENT TO REQUIRE

EMISSIONS REDUCTIONS NECESSARY TO

MEET CAA HEALTH, WELFARE AND

ENVIRONMENTAL GOAL G..........cccccessssesesssesseserensees 19

SPD cccepenencesmraptantuinianicceneetnensasettttinneseieimanemiacnengsnes 21

iil

TABLE OF AUTHORITIES

CASES:

Alabama Power v. Costle, 636 F.2d 323 (D.C.

IT: IIIT iiscalielceniacanihiiicdenleahiaenaheninpsendesdatoniaiiiician

Alaska Department of Environmental

Conservation v. EPA, 540 U.S. 461 (2004) .........

New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005)..........

United States v. Duke Energy Corp., 411 F.3d

EEE: CIEE écincncacscotnisessenintbeccyseseenscsnencentn

Wisconsin Elec. Power Co. v. Reilly, 893 F.2d

ge | Eero ENE

STATUTES:

Clean Air Act, 42 U.S.C. 7401 ........cccceccececesssecsseseeeees

Small Business Regulatory Enforcement

Fairness Act of 1996, 5 U.S.C. 801......................

es Se seo cicctcrnicstintedictncnainiiianenioaninnindessinn

Conn. Gen. Stat. Ann. §29-20-108 .0..........ecceecceeeeees

Ga. Code Ann. §46-3-125 ..........cceccecessessseesscsseseeceeenes

La. Rev. Stat. Ann. §33-4545-2 oo...cccceeccecceeeeeeneeenes

Mass. Gen. Laws ch. 164, §47C..0.0.......ccccceceseceeeeeeees

Miss. Code Ann. §77-5-703(C).........cscccssceseeeeeeeeeeeeees

Pe DRT. GREE, CEFR IIID crccsececescosccseteseresecsoctenennesooves

RULES:

LE EE ae ae oem

Page

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iv

TABLE OF AUTHORITIES—Continued

Page

REGULATIONS:

BOC Be GIS RO certeeetenmennenintenminisiitin 1]

FEDERAL REGISTER:

45 Fed. Reg. 52,676 (Aug. 7, 1980) ).........cccceceseesees 16

63 Fed. Reg. 57356 (Oct. 27, 1998). ........cecscceeceeeeeees 20

OTHER AUTHORITIES:

EPA New Source Review: Report to the

TENNENT NTE Nes Ce 9

IN THE

Supreme Court of the Gnited States

No. 05-848

ENVIRONMENTAL DEFENSE, ET AL.,

Petitioners,

Vv.

DUKE ENERGY CORPORATION,

Respondent.

On Writ of Certiorari to the United States Court of Appeals

for the Fourth Circuit

BRIEF AMICI CURIAE OF

THE AMERICAN PUBLIC POWER ASSOCIATION

AND THE NATIONAL RURAL ELECTRIC

COOPERATIVE ASSOCIATION

All parties consent to the filing of this brief. !

STATEMENT OF INTEREST

Ne OF AMICI CURIAE

Created in 1940 as a non-profit, non-partisan organization,

amicus curiae the American Public Power Association

(APPA) is the service organization for the nation's more than

' No party or its counsel authored this brief in whole or in part nor

made a monetary contribution to amici for the preparation or

submission of it. This brief is filed with the written consent of all

parties pursuant to Rule 37.3(a). Copies of the requisite consent

letters have been filed with the Clerk.

2

2,000 community-owned and community-operated electric

utilities that serve more than 43 million Americans in 49

states or approximately 14 percent of the nation’s electricity

customers. 1,400 of the 2,011 public power systems in the

United States serve communities with populations of 10,000

or fewer. Thirty percent or 29,175 MW2 of APPA’s

members’ power generating capacity is coal-fired.

Although the vast majority of the public power systems is

owned by cities and towns, a number of counties, public

utility districts and even a handful of states have public

power systems. Most public power systems, especially the

smaller ones, are governed by a city council, while others are

overseen by an independently elected or appointed board.

Public power has a strong environmental protection record

and a reputation for reliable and affordable power service.

APPA’s mission is to assist its members in ensuring that

ae-quate, reliable electricity is available to their customers at

a reasonable price while protecting the environment.

Amicus curiae the National Rural Electric Cooperative

Association (NRECA) was formed in 1942 by the nation’s

rural electric cooperative leaders dedicated to electrifying

vast regions of the country and providing reliable and

affordable electric power through electric cooperative entities.

Today, NRECA serves as the national service organization

for 930 not-for-profit rural electric cooperatives that provide

electric service to 39 million Americans in 47 states. Each

electric cooperative is incorporated as a private entity in the

state in which it resides and has a lega! obligation to provide

2 “Megawatt” or “MW” is used to describe the electric generating

(output) capacity of a facility. Another measure of capacity used

by utility engineers describes the capability of a unit to burn fuel

(i.e., its heat input capacity) and is expressed in terms of million

British Thermal Units (mmBtu) per hour. Because unit emissions

are directly related to the amount and type of fuel burned in that

unit, a unit’s capacity to emit is directly related to the unit’s heat

input capacity.

3

reliable electric service to its customer-members.

Collectively, cooperatives serve all or portions of 2,500 of

the nation’s 3,128 counties and their service areas cover 75

percent of the U.S. landmass.

The scarcity of reliable and affordable clectric power in

many regions of the United States in the late 1960’s created a

need for cooperative self-generation of electric power.

Today, sixty-five rural electric generating and transmission

cooperatives (G&Ts), which are owned by the distribution

cooperatives they serve, generate and transmit power to 670

of the 865 distribution cooperatives. Overall, cooperative

G&T generation produces 41 percent of all distribution

cooperative needs. The need to provide reliable, primary

(baseload) and affordable electric power effectively dictated

coal as the fuel of necessity rather than natural gas and

nuclear power. Presently, 80 percent of NRECA’s members’

cooperative generation or 23,000 MW is coal-fired. The

remaining distribution cooperatives receive power directly

from other generation sources within the electric utility sector,

a significant portion of which also originates from coal-fired

generation.

NRECA’s cooperative members are dedicated to offering

their member-consumers a broad array of electric generation

choices including “green power.” Today, about two-thirds of

the cooperatives offer a green or renewable power option.

The majority of this generation is by wind or biomass.

Amici curiae, who are owned by their communities or

customers, represent smaller electric generating entities.

Collectively, amici curiae comprise a significant portion of

the electric generation and distribution industry which, in

turn, serves over 25 percent of electricity customers and over

80 percent of the landmass in the United States. For this

3 Over 95 percent of the members of APPA and NRECA are

considered “small entities” under the Small Business Regulatory

Enforcement Fairness Act of 1996, 5 U.S.C. 801 ef seg.

4

reason, amici curiae provide a unique and invaluable

perspective on the effect that the Environmental Protection

Agency’s (EPA’s) enforcement interpretation of New Source

Review (NSR) can have on the ability to supply reliable and

affordable electric service throughout the United States.

SUMMARY OF ARGUMENT

Requiring NSR permitting under EPA’s NSR enforcement

interpretation when a small electric utility merely takes a

boiler offline to undertake the repair or replacement of a

broken component without increasing the unit’s permitted

capacity to emit (i.e., its emissions rate, unaffected by hours

of operation, or its hourly maximum achievable emissions

rate) is inconsistent with the Clean Air Act, 42 U.S.C. 7401

et seg. (CAA).* It also would be costly, potentially

financially crippling and environmentally unnecessary for

anall public and rural electric generating systems that service

a significant portion of the U. S. population and landmass.

Accordingly, to ensure that these smaller utilities can

continue to meet their duty to provide reliable and affordable

electric service, this Court should affirm the decision of the

United States Court of Appeals for the Fourth Circuit in

United States v. Duke Energy Corp., 411 F.3d 539 (4th

Cir. 2005).

4 Amici curiae’s primary purpose in filing this brief is not to repeat

the reasons why EPA’s position is inconsistent with the letter and

the spirit of the CAA. Instead, amici curiae can provide the Court

with insight into the practical effect of the position advocated by

Petitioners and EPA.

5

ARGUMENT

I. REQUIRING NSR PERMITTING, A LENGTHY

AND COSTLY PROCESS, FOR REPAIRS THAT

DO NOT INCREASE A_ FACILITY’S

ACHIEVABLE HOURLY EMISSIONS RATE

WOULD SERIOUSLY IMPEDE THE ABILITY OF

PUBLIC AND RURAL COOPERATIVE

GENERATING SYSTEMS TO SUPPLY

RELIABLE AND AFFORDABLE ELECTRIC

POWER.

A. Public Power and the Nation’s Electric

Cooperatives Have a Duty to Provide Reliable

and Affordable Elec ric Service.

Public power and electric cooperatives have a duty to

provide reliable and affordable electric service to their

customers. That duty to serve their constituents comes from

state statutes and common law that require the public power

systems > and cooperatives © to provide an adequate,

dependable and economical supply of electric power.’

5 See, e.g., Ga. Code Ann. §46-3-125 (public power authority is

charged with taking all “necessary or desirable action in order to

provide or make available an adequate, dependable, and

economical supply of electric power and energy and related

services”), Miss. Code Ann. §77-5-703(c)\ municipalities owning

electric generation and/or distribution systems have obligation to

provide most adequate, reliable and economical source of electric

power), Neb. Rev. Stat. §70-1403 (public power has obligation to

provide adequate, reliable and economical source of electric

power).

© See, e.g., Conn. Gen. Stat. Ann. §29-20-108 (municipal electric

utilities can form cooperative public corporations to provide

efficient, low cost and reliable electric power), La. Rev. Stat. Ann.

§33-4545-2 (power authority authorized to cooperate with electric

power cooperative associations to ensure an adequate, reliable and

economical supply of electric power), Mass. Gen. Laws ch. 164,

B. Small Electric Generating Systems Often Rely

On Just a Few Units and Must Be Able to Make

Repairs to a Unit Without Taking that Unit

Offline For an Extended Period of Time.

Many factors affect the amount of actual electric generation

produced by steam from a boiler or “emissions unit” of a

coal-fired electric generator — seasonal fluctuations in electric

demand, the availability of other units in the system, the cost

of one unit’s generation relative to other units, the cost of

electricity from other producers and even the annual rainfall,

which affects the availability of electricity from hydroelectric

power plants, which, in turn, affects the demand for

electricity from fossil fuel electric generating units. A

planned or forced® outage at one unit in the system will

paquire immediate increased production at another unit

within the system or region.

From time to time, public power and the electric

cooperatives must take a unit offline to make a repair. Such

a repair characteristically involves replacing a failed or worn

component with a new or refurbished one. Typical examples

of repair work to a coal-fired electric generating boiler are

replacing steam tubing, water pumps and valves. These

types of repairs allow the generating unit to maintain its full,

legal, operational capabilities. EPA’s position in the case

before this Court is that many common (and often minor)

§47C (municipal plant may form cooperative to provide efficient,

low cost and reliable electric power).

7 The cooperatives also have additional duties to serve originating

from service agreements with consumers, corporate bylaws and

articles of incorporation and, for those who acquire financing from

the federal government, provisions in associated loan agreements.

8 Forced outages are unanticipated and/or unplanned periods when

a boiler is brought offline to perform necessary repairs.

7

repairs to units trigger NSR because they are physical

changes that allow the facility to increase its hours of

operation to levels that the unit was capable of achieving or

had achieved in the past.

Although the larger electric generating systems have

dozens of units that are subject to the CAA’s NSR program,

public power and rural electric cooperative power systems

frequently have only a single commercial-sized coal-fired

unit that serves thirty to fifty percent (or in some instances

100 percent) of the system’s electric load. For example, 75

percent of all cooperative generators have a single coal unit

that represents over twenty percent of all the electricity sold.

Twenty-five percent of all cooperative generators have a

single unit that represents thirty-three percent of all

electricity sold. These small systems cannot take a unit

offline a moment longer than necessary to make a repair

without incurring potentially huge financial impacts if

substitute power must be purchased on the wholesale market.

C. Requiring NSR Permitting For Repairs That Do

Not Increase Achievable Hourly Emission Rates

Would Present Small Utilities With a Hobson’s

Choice.

A forced outage in an electric generating system requires

fast and deliberate action. The stakes are particularly high

for smaller systems because, as noted above, a major portion

of the system’s ability to provide electric power to its

consumers is no longer available. Unfortunately, under the

position advocated by Petitioners, when a small system

makes a repair that does not increase the unit’s achievable

hourly emissions rate but may allow the unit to increase

utilization of existing capacity within permit limits, it will be

faced with three equally untenable choices: (1) Obtain an

NSR permit which takes on average 18 months, which would

not be a feasible response to an immediate forced outage;

8

(2) Go through a CAA permitting process and obtain a

“synthetic minor” permit? that effectively imposes permanent

legal limits on the unit’s operations, which process also

cannot be completed expeditiously;!° or (3) Conclude that

no NSR permit is required (for example through a

complicated and uncertain ‘“actual-to-projected actual”

emissions increase analysis) and risk enforcement action

including massive civil liability to the utility and potential

personal criminal liability to the responsible owner and/or

operator if, after retrospective review, the regulatory agency

believes that NSR was applicable.

Under EPA’s enforcement interpretation, during any

planned or forced outage, an operator must determine if a

repair will trigger NSR applicability. In many cases, even

with a planned outage, the actual physical repairs required

are not ascertainable until the unit is actually offline and the

yeernal parts exposed and examined by utility personnel.

This NSR applicability determination can be extremely time-

consuming, complex and uncertain, given varying

interpretations posited by EPA over the years as well as in

this case.

9 A CAA permitting process in which a utility obtains a synthetic

minor permit is a process in which the unit’s operator voluntarily

imposes new lower legal limits on the unit’s allowable emissions,

which in most cases results in limiting the total number of hours

the unit is allowed to operate in a year.

10 A unit may be forced to accept a permit limit on its hours of

operation because the approval and installation of Best Available

Control Technology (BACT) emission controls is not a feasible

response to a forced outage that needs immediate repair. Although

usually shorter than the 18 or more months required to obtain an

NSR BACT permit, depending on the jurisdiction, such a synthetic

minor permit still requires a minimum 30 — 180 day public review

period.

9

1. The NSR Permitting Process is Expensive,

Time-consuming and Often Not Feasible.

The NSR review process consists of the preparation and

submission of a permit application by the owner/operator of

the unit, followed by an extensive review of the application

by the state and/or federal permitting authority. The

application includes an assessment of the air quality impact

of the proposed major modification, an assessment of its

potential effect on national parks or wilderness areas and an

assessment of retrofitted pollution controls called the best

available control technology (BACT) analysis. This review

can take up to two years or more. Many states, in

implementing Federal Clean Air Act requirements,'! provide

for a 30-day application completeness review, a 60-day

agency technical review, a 30-day public comment period

and a 30-day period for a public hearing. In some instances,

the 30-day completeness review re-starts if application

deficiencies are later identified. The BACT determination is

one of the most complex portions of the NSR process

involving a technical feasibility evaluation of alternative

emissions control technologies, cost evaluations of each

technology alternative and an assessment of the

environmental and energy impacts of each alternative. Thus,

the time period from submission of the application to

approval of the permit is typically 18 to 22 months. See, e.g.,

Alaska Department of Environmental Conservation v. EPA,

540 U.S. 461, 515 (2004)(process took 18 months). Even

EPA in its report to President Bush on NSR admitted that the

entire NSR permit process typically lasts between 7 to 22

months. EPA New Source Review. Report to the President

(2002).

'! These requirements are implemented through CAA State

Implementation Plans (SIPs).

10

This period does not include the time necessary to prepare

the application (which can take six months or more) or to

install any resulting controls, which could take years. Even a

NSR_ non-applicability determination typically takes 18

months. If, in order to undertake common repair and

replacement projects, a small utility is faced with the time it

takes to prepare an NSR application, complete the permitting

process, defend legal challenges to the permit and retrofit any

required controls, that small utility may be unable to serve its

customers and, accordingly, may have to forgo such projects.

The NSR permitting process is not only expensive'? and

time-consuming, but the resulting controls can add tens of

millions of dollars in capital installation and annual operating

costs to a system. Moreover, during NSR applicability

determinations and permitting review, a public or cooperative

utility may not be able to provide electricity to its consumers

wth existing generating capacity within its system, and thus

may be forced to buy substitute power from others at

uncertain and usually high wholesale market rates.

For all of these reasons, amici curiae are extremely

concerned because repairs that only maintain a unit’s full

operational capabilities, but do not increase a_ unit’s

maximum hourly achievable emission rate would require

NSR permitting under the position now advocated by EPA

and Petitioners. It is difficult to believe that, by means of a

technical amendment in 1977, Congress intended to expand

the NSR program so radically and to create such a regulatory

obstacle to the supply of reliable and affordable electricity to

millions of households across the nation. Indeed, EPA’s own

interpretation and implementation of the program for nearly

two decades never suggested that NSR could be triggered by

common repairs that merely maintained a facility’s operating

\2 The air permitting application can cost as much as $500,000,

in-luding an assessment of BACT that can cost between $15,000

and $50,000.

11

capabilities without ‘ncreasing the facility’s maximum hourly

emissions rate.

2. Obtaining a Synthetic Minor Permit is Not a

Rational, Economically Feasible or Financially

Prudent Alternative.

Petitioners suggest that one viable option to avoid the full

NSR permitting process is to limit future potential annual

emissions to significant emissions increase levels '? above

representative past emissions by obtaining a synthetic minor

permit. This approach is not at all viable. Avoiding the

lengthy NSR permitting process by artificially limiting unit

utilization would be an enormously expensive and unwise

alternative and is not contemplated by EPA’s regulations.

See Wisconsin Elec. Power Co. v. Reilly, 893 F.2d 901, 917

n.13 (7" Cir. 1990).

Generating units are utilized or “dispatched” in order of

lowest to highest unit operating costs. Even “baseload” coal-

fired utility units rarely operate at more than 80% of annual

capacity factor.'* Lesser utilized or “intermediate load” units

operate at lower annual capacity factors but must be available

to meet increasing electric demand during times of peak

usage within the year or long-term outages of baseload units.

In addition, many electric generating units are designed to

meet both current and future customer electricity demands on

utility systems and thus may not be operated at full

operational capacity for a number of years until electricity

demand grows. In such cases, these intermediate load units

'3 The NSR definition of a significant increase for SO2, NO, and

volatile organic compounds (VOC) is 40 tons but other

significance levels vary. 40 C.F.R. §52.21(b)(23).

'4 “Capacity factor” is the ratio of actual MWH generated in a year

by the unit to the MWH that would be generated if the unit

operated continuously at maximum output.

12

will be ramping up to baseload use. Likewise, some units

may go for years with very minimal operation in areas of the

county where hydro-electric power is the baseload economic

choice and rainfall is adequate for years or even decades.

Under Petitioners’ formulation, each time an operator

makes a repair and accepts a synthetic minor NSR permit

limit, it would have to restrict annual future usage based on

its recent historic levels of operations to avoid the full NSR

permitting process. Under the most recent NSR permitting

process, typically a unit’s future operation under a synthetic

minor permit would be limited to an annual avera~ - emission

based on the 24 consecutive months of highest 0; -ration over

the previous five years. Thus, a small system with a unit

under a synthetic minor permit limit loses its ability to use its

needed and otherwise available and already permitted excess

capability, and faces financially difficult choices in replacing

that ‘ost generation.

Taking a synthetic minor permit in response to a physical

change in lieu of full NSR permitting may appear to be the

most expedient option. This alternative, however, is

typically very expensive. To demonstrate, NRECA

aggregated for all cooperative coal-fired generating units the

difference between their presently permitted electric

generation (including annual emissions) and their generation

(including annual emissions) if each unit were limited to its

annual generation average of the highest 24 consecutive

months within the five years from 2000 to 2004 using U.S.

Department of Energy, Energy Information Administration

(EIA) official data (Form 767). Summing this information

for all cooperative units results in a combined generation loss

of 18.28 percent. Stated differently, of the 23,089 MW of

NECRA member cooperative coal-fired capacity legally

available, the synthetic minor limitations would result in the

13

equivalent of over a 4,220 MW loss,'> which equates to

effectively eliminating over seven large commercial

generating units, representing over $7 billion in replacement

coal-fired generation.'® This lost generation capacity would

be enough to provide electricity to over 3.3 million

residential homes. !’

This loss of over 18 percent of cooperative generation

capacity that would result if Petitioners’ view of NSR were

the law simply is not a viable option for small electric

systems and cannot be justified to the customers of a public

power system or to the members of a not-for-profit

cooperative. The diminished unit availability would impact

capital cost recovery, negatively affect financial credit ratings,

and increase rates as additional generation facilities or the

purchase of substitute power would be needed to make up for

the lost generation capacities. Thus, synthetic minor

permitting is not a rational, economically feasible or

financially prudent alternative for the communities that own

public power and for the consumers that own cooperative

systems. This result certainly could not have been what

Congress intended.

'5 Technically, the loss is not one of capacity (MW), but one of

generation output, best expressed in a megawatt-hour (MWh)

metric. The MW capacity loss cited here is derived by dividing

the MWh loss by 8,760, the total number of hours in a year.

16 The replacement generation cost estimate of $1,700/KW

(kilowatt) installed capacity is based on Department of Energy,

Energy Information Administration (EIA) estimated “overnight

cost” of new coal-fired generating adjusted to include a 10 percent

contingency factor reflecting change orders in contracts during

construction, a 4 percent real dollar increase in materials and labor,

and a 7 percent cost of financing during five years of construction.

'7 This calculation is based on average sales to residential

consumers based on EIA Electric Sales Revenue and Price, 2004

publication.

14

3. For Even a Short Period, the Cost of

Replacement Power During NSR Permitting

Could Be Crippling For Many Public Power

and Rural Cooperative Systems.

The cost of replacement power purchased on the spot

wholesale electricity market can be considerably more

expensive than the power produced by a utility’s own

generating facilities because the price of substitute generation

is market-based. The difference between the small utility’s

own generation cost and the price of substitute generation

purchased on the wholesale market is especially exacerbated

ai times of peak demand such as during summer or winter

because the wholesale market price of electricity is based on

the cost of the last and most expensive generation, i.e., the

last to dispatch in the region. One large APPA member in

the West has seen the market price of wholesale electricity

range from $50 to $400 per MWH during summer hours or

other high load periods — a 700% price differential.

To illustrate the financial impact of the high cost of

replacement power, for every twenty-four hour day a

baseload commercially sized 600 MW unit is offline, the

difference between the cost of replacement power and the

cost of power generated by the unit can easily amount to

$576,000 per day, over a 330% increase.'* Taking a

'8 This result comes from standard engineering calculations

assuming 80% annual capacity usage of the 600 MW unit and

8,760 hours in a year. Baseload generation costs of $15/Mwh, a

realistic conservative average, and replacement power costs of

$65/MWh were used. The replacement power cost is also a

conservative estimate based on the average future prices derived

from the five regional electricity trading hubs of PJM, Cinergy,

Entergy, ERCOT, and Palo Verde over the twenty-month forward

period beginning on August 2006. This information is provided by

the energy brokers Amerax, Preban and TFS; and pricing reports

in Platt’s Megawatt Daily and NYMEX. Transmission costs,

which can be very substantial, were excluded from this calculation.

15

synthetic minor permit for the unit assuming an 18% loss of

capacity, a likely reduction discussed earlier, would cost the

small utility over $70 million for the first 18 months for

substitute power. This last figure, however, ignores the costs

of supplying power after the initial 18-month period. To

replace the 18% loss of capacity quickly, in 18 months, gas

generation would likely be constructed or purchased,

resulting in an additional cost of almost $69 million, '°

making the combined costs of supplying substitute

generation while other generation is built plus the new

generation total $139 million. Thus, in taking a commercial

unit offline in a public power or cooperative system for even

a few months while that system seeks an NSR permit, an

NSR applicability determination or even a synthetic minor

permit, the system would have to purchase replacement

power at significantly higher prices and, ultimately, a

significant rate increase could be necessary to cover the

higher cost of purchased power and potentially building new

power. Depending on the relative financial impact, credit

ratings and potentially even the financial stability of these

small systems could be very negatively affected.

Thus, during the 18-month NSR permitting process (or

even in the synthetic minor permitting process), the small

system would be forced to purchase replacement power in

the wholesale market, which, depending on the prevailing

rates, could spell severe economic problems for the system.

Moreover, accepting an artificial cap on operations by means

of a synthetic minor permit and operating well below

'9 This calculation assumes combined cycle gas generation capital

costs of $625/K W based on the EIA 2006 Annual Energy Outlook.

The unit could be permitted in an expedited process as a Clean Air

Act minor source and built in only 18 months. The calculation

does not reflect the actual cost of power generation from this type

of gas unit; it reflects only construction cost. Considering

historically high natural gas prices, the overall cost of generating

power from this unit operation would be considerably higher than

the coal-fired generation it would replace.

16

capacity - - which systems might be forced to do - - would

significantly impair the capital of the system.

Faced with these obstacles, under Petitioners’ view, small

generating systems would find it difficult, if not impossible,

to meet their obligation to provide reliable and affordable

electric service. Congress hardly could have intended to

require small systems to undergo the lengthy and costly NSR

permitting process every time they made a repair to a unit

that did not increase its maximum achievable hourly

emissions rate, and EPA could not have done so in its

regulations without disclosing the extraordinary expansion of

the NSR program it was contemplating and assessing the

equally extraordinary economic impact of such an expansion.

Yet, when it promulgated the 1980 NSR Rules, EPA’s

economic assessment showed no such expansion. See 45 Fed.

Reg. 52,676, 52,729 (Aug. 7, 1980).

4. Requiring NSR Permitting For Repairs That

Do Not Increase a Unit’s Achievable Hourly

Emissions Rate Would Subject Small Utilities

to Constant NSR Permitting or Compromise of

Capacity.

The problems generated by subjecting units to the NSR

permitting process for repairs that do not increase the unit’s

maximum achievable hourly emissions rate are multiplied by

the frequent shifts in generation loads or hours of operation

of a unit within a small system. As set forth above,

numerous planned and unplanned factors, including seasonal

demand, forced outages and rainfall, affect the usage of a unit.

If small utilities are required to go through the NSR review

process for common repairs, such as those targeted by EPA

in the NSR enforcement initiative, small utilities will be in a

constant NSR permitting cycle.

Under EPA’s enforcement interpretation, every repair or

replacement of a component such as a tube assembly, pump

17

or valve - - which occurs frequently over the life of a

generation unit - - would put the operator in the same

predicament — undergo a lengthy NSR permitting process and

install controls or limit capacity. If the utility chooses the

more expedient option of a synthetic minor permit, it will

find itself in a downward spiral, successively limiting its

operations further and further below its permitted, full

operational capabilities.

The dilemma faced by a small electric system

contemplating repairs to a unit is exacerbated by the

methodology for determining whether an annual emissions

increase would occur if that methodology requires a

“projection” of likely future utilization within permitted

capacity. Such a projection is, at best, fraught with

complexity, subjectivity and uncertainty.?°

In the enforcement cases, EPA posited an outcome-

determinative methodology that assumes that whenever a

component that caused forced outages in the past is repaired,

the repair will inexorably lead to “recovered” utilization and

thus an increase in hours of operation and, therefore,

emissions. This approach is in contrast to the NSPS

maximum hourly emissions test, which is purely an

engineering evaluation of the fuel burning (and therefore

emitting) capacity of the unit in question.

20 Any emissions increase test that is based on projected utilization

requires seer-like knowledge because it must be applied at the time

of the proposed project and prior to post-project operation, when it

is impossible to predict all future unit operational parameters that

may affect emissions. For example, fuel characteristics such as

inherent sulfur concentrations can vary unpredictably over time,

resulting in annual unit emissions increases unrelated to any

physical change; and seasonal generation demands on the unit due

to weather or unit outages can force a greater operational burden

on the unit than predicted. Additionally, many other unforeseeable

factors can cause subtle unit emission increases unrelated to any

physical change.

18

Thus, small utilities in particular will face significant

uncertainty and expense because an NSR applicability

determination implicates systems having only several units

whose annual production and operating hours vary

considerably as these units experience differing maintenance

Outage times and production rates to meet dispatch

obligations on a year-to-year basis. The position advocated

by EPA and Petitioners, which is not consistent with the

requirement for a “modification” as determined under the

New Source Performance Standards (NSPS), will make it

impossible for small electric utilities to maintain their units

as required or make desirable efficiency improvements.

Operators will hesitate to take units offline to replace

components to maintain unit performance because of the

complicated analysis that would have to be performed to

make an educated guess as to the risk that the repair will

trigeer NSR review - - a complicated analysis that is always

subject to second-guessing because no one can accurately

predict how the myriad of factors that affect the utilization of

one unit within the system will change in the future.

Certainly, Congress could not have intended to subject

small electric systems to such expense and uncertainty every

time a unit undertakes the type of projects targeted in EPA’s

enforcement initiative. Yet, this will be precisely the result

so long as the test required for NSR applicability is not keyed

to a repair that actually increases a unit’s maximum

achievable hourly emissions rate.

5. The Potential Liability For Public Power and

Cooperatives is Great.

If an operator errs in forgoing NSR permitting, the

potential CAA liability is $32,500 per day per occurrence

(i.e., per pollutant). If sulfur dioxide (SO2) and nitrogen

oxides (NOx) triggered NSR review bu: the utility failed to

19

realize it for a year 27! , the potential liability for

noncompliance is $23,725,000 (365 x 2 x $32,500). 42

U.S.C. §7413(b). The utility could also face injunctive relief,

including the cost of BACT, as well as potential personal

liability.

Subjecting small utilities to the NSR applicability process

for a mere increase in hours of operation after a common

repair creates uncertainty over whether NSR permitting is

required. Cooperatives and public power systems selecting

any one of the Hobson’s alternatives would face significant

financial burdens because of loss of ability to utilize full

generation capabilities of units that have required very

significant capital investments, as well as additional costs to

provide substitute generation to avoid abrogating their duty

to their customers to provide reliable and affordable electric

service.

Il. USE OF THE NSPS’ DEFINITION OF

"MODIFICATION" WILL NOT CIRCUMVENT

CONGRESS' INTENT TO REQUIRE EMISSIONS

REDUCTIONS NECESSARY TO MEET CAA

aa. WELFARE AND ENVIRONMENTAL

Contrary to Petitioners’ claims, rejection of EPA’s

enforcement interpretation will not circumvent Congress’

intent to require emissions reductions necessary to meet CAA

health, welfare and environmental goals. A significant

portion of public power and cooperative coal-fired generation

already meets NSPS requirements and/or has been through

2! As discussed in Alabama Power v. Costle, 636 F.2d 323, 401

(D.C. Cir. 1979), a facility’s “net” emissions across all the units at

a facility over a five-year contemporaneous period are considered.

See also, New York v. EPA, 413 F.3d 3 (D.C. Cir. 2005).

pan 20

New Source Review, and is equipped with modern pollution

controls.

Over 60 percent of public power’s coal-fired generation

already meets applicable NSPS requirements under the CAA.

Likewise, over 50 percent of cooperative coal-fired

generation already meets applicable NSPS requirements

under the CAA. Additionally, 20 percent of all cooperative

generation has gone through NSR.

Moreover, even those units that have not been through any

form of new source review are well-regulated and will

continue to be subject to other, increasingly stringent CAA

programs that ensure that these facilities are well-controlled

without interfering with their duty to serve. For example,

due to subsequent CAA regulatory mandates effectively

forcing pollution control retrofits on the remaining and older

cooperative units, 90% percent of cooperative generation

usir~ high sulfur coal is equipped with flue gas

desulfurization (FGD) units to control sulfur dioxide (SO)

emissions, the primary pollutant associated with coal-fired

generation.”? In addition, virtually all cooperative generating

capacity in the Eastern United States, equaling about 6,000

MW, is also retrofitted with state-of-the-art nitrogen oxides

(NO,) controls, Selective Catalytic Reduction (SCRs),

because of EPA’s NO, SIP Call requirements promulgated

in 199823, to control Eastern ozone. Almost all cooperative

coal-fired generation is also equipped with low-NO, burner

technology regardless of where the units are located.

Thus, even though much of cooperative and public power

coal-fired generation is newer and/or equipped with state-of-

the-art pollution controls, electric cooperative generation and

public power units would still be subject to the lengthy and

costly NSR applicability process under EPA’s NSR

22This number includes one commercially sized unit where the

FGD retrofit is ongoing.

23 See 63 Fed. Reg. 57356 (Oct. 27, 1998).

21

enforcement interpretation, which would jeopardize their

ability to provide reliable and affordable electric service.

CONCLUSION

Under Petitioners’ view of NSR, the operator of a small

electric utility who merely needs to replace a broken part

would be forced to endure a lengthy NSR process and to

navigate through a test that is so complex, confusing and

fraught with subjectivity that it has gone through years of

EPA iterations, interpretations and court battles. For the

foregoing reasons, the judgment below should be affirmed.

Respectfully submitted,

JANET PITTERLE HOLT*

738 West Glebe Road

Alexandria, VA 22305

(703) 684-6102

RAE E. CRONMILLER

RICHARD H. ROBINSON

NRECA

4301 Wilson Boulevard

Arlington, VA 22203

(703) 907-5791

* Counsel of Record Counsel for Amici Curiae

September 15, 2006